California should have enough capacity to get through this summer’s peak demand but dwindling hydropower and limited imports during late-season heat waves could strain supply, CAISO said Friday.
“Projections for summer 2020 show that the CAISO faces a low but somewhat increased risk of encountering operating conditions that could result in operating reserve shortfalls than was projected for 2019,” CAISO’s annual Summer Loads and Resources Assessment concluded.
CAISO’s summer demand is expected to peak at 45,907 MW, a negligible increase from last year’s weather-normalized peak of 45,826 MW. The increased risk this year compared with 2019 comes from lower-than-normal hydro conditions that could be “particularly impactful in late summer” when reservoirs are at their lowest.
CAISO’s breakdown of available 2020 summer peak capacity shows gas remains a major resource. | CAISO
California’s snowpack from winter storms is the primary source of water during the state’s dry months from late spring through early fall. The statewide snow-water content in mountainous areas, including the Sierra Nevada, was 63% of average at its peak on April 7, the report said.
The state’s major reservoirs were filled to 101% of average in April, but the snow that gradually melts and refills the reservoirs is far less than last year. On April 11, 2019, the statewide snow-water content was 161% of average.
Pacific Northwest hydropower, a major source of imports for California, is expected to be about the same as last year. For instance, the Northwest River Forecast Center projected the April-to-August reservoir storage at The Dalles Dam on the Columbia River to be 95% of average. It was 94% of average in 2019.
California, however, is competing more with other Western states for a tightening supply of electricity as coal plants retire. (See Western Resource Adequacy Program in the Works.) Moreover, the state’s peak demand has shifted to later in the day, as solar energy diminishes and stops.
CAISO reiterated its concern with the situation last week.
“The CAISO will be at the greatest operational risk of a system capacity shortage later in the summer if hot weather occurs that extends beyond the CAISO footprint and diminishes the availability of surplus energy in neighboring balancing authorities for imports into the CAISO during peak hours when solar production is near or at zero,” it said.
The 2020 summer report didn’t assess risk from transmission outages because of wildfires but acknowledged it “could hinder imports during critical supply conditions.”
Planners didn’t have enough data to factor in the effect of decreased load on summer demand from the COVID-19 crisis and California’s stay-at-home order.
After Gov. Gavin Newsom issued the order in March, weekday loads were down by about 7.5% during peak-demand times and down 5% during off-peak times; weekend load reductions were 3% during peak demand and 1% off-peak, CAISO has said. (See Western EIM Governing Body Hears COVID-19 Updates.)
CAISO and the California Public Utilities Commission have been worried about capacity shortfalls that were projected to start as early as this summer and grow significantly worse beginning in summer 2021.
The CAISO assessment could allay fears about capacity shortfalls this summer, but next year may be another story.
Last September, Mark Rothleder, CAISO vice president for market policy and performance, told the CPUC that the state was facing shortfalls to its capacity needs, including a 15% planning reserve, of 4,400 MW in 2021 and 4,700 MW in 2022. (See CAISO, CPUC Warn of ‘Reliability Emergency’.)
“The issue is not so much at the peak hour,” Rothleder said. “It’s at the near-peak hour as the sun goes down.”
CAISO and the CPUC have been working to address the issue. The commission ordered some older once-through-cooling plants that were scheduled to retire to remain open through 2023. It also ordered all load-serving entities under its oversight to collectively procure 3,300 MW of capacity, on a basis proportional to projected load, by August 2023. (See California PUC Votes to Keep Old Gas Plants Operating.)
Incumbent transmission owners in PJM won a victory last week as the Planning Committee endorsed creation of a new regional targeted market efficiency project (RTMEP) process that would be excluded from competition. The new process will involve backward-looking analysis to address persistent congestion not identified in the forward-looking planning model.
The PC endorsed a combined proposal by American Electric Power and FirstEnergy on the RTMEP process with 56% support. The AEP-FE package, which would exempt RTMEPs from competition, edged out PJM’s proposal (55% support), which called for 30-day competitive windows to select the developer.
The two packages were otherwise identical. They would calculate benefits based on the average of the past two years of day-ahead and balancing congestion, adjusted for outage impacts. To be approved, a project would have to recover the project’s capital cost within four years.
AEP-FE’s proposal for the benefit calculation metric also was preferred, winning 54% to PJM’s 52%. AEP and FE would employ a single-draw Monte Carlo simulation, with simulations for both Reliability Pricing Model and Regional Transmission Expansion Plan (RTEP) years. PJM proposed averaging Monte Carlo results and running them on RTEP, RTEP+3 and RTEP+6 years. Projects must have a capital cost under $20 million and be in service within three years.
The Independent Market Monitor’s proposals on those two components each received less than 20% support.
PJM’s proposed window for capacity drivers won 52%, besting the IMM’s proposal with 25%. (AEP and FE did not offer an alternative window.) PJM proposed a 24-month cycle for energy drivers and a 12-month cycle for capacity.
AEP and FE said the interregional PJM-MISO TMEP planning process has produced six projects costing $120,000 to $6.7 million, none of which involved greenfield projects and each of which was assigned to incumbent TOs. Three involved line reconductoring; two required replacing or upgrading terminal equipment; and one was for reconfiguration of a ring bus. The companies said they expected that regional TMEPs would produce similar projects.
The PC’s May 12 endorsement culminated 18 months of work the Market Efficiency Process Enhancement Task Force and sets up final votes at the Markets and Reliability Committee. Each issue in the package needed at least a 50% vote to move on to the MRC for a final sector-weighted vote.
Greg Poulos, executive director of the Consumer Advocates of the PJM States, asked when manual language will be drafted for the AEP package to be voted on. PJM’s Jack Thomas said manual language or government document language will be drafted for the first read at the June MRC meeting but could be pushed back to the July meeting depending on how long it takes to put together.
Changes Approved to CISO Issue Charge
The PC approved Exelon’s revisions to the Critical Infrastructure Stakeholder Oversight issue charge over the objection of the original sponsor, the D.C. Office of the People’s Counsel.
Exelon’s redline of the issue charge that was originally endorsed by stakeholders in December was approved by a 61% vote. The D.C. OPC had proposed the issue charge in response to transmission owners’ decision to file a new Tariff Attachment M-4 for the planning of critical infrastructure protection (CIP-014) mitigation projects (CMPs). (See “Critical Infrastructure Mitigation,” PJM PC/TEAC Briefs: Dec. 12, 2019.)
The original issue charge said it would consider whether “procedures that provide stakeholder oversight of CMPs and CIP-014 facilities are appropriate.”
Exelon’s revision eliminates the term “stakeholder oversight,” saying instead that it will “evaluate whether procedures are appropriate for stakeholder review of measures to avoid a transmission facility from becoming a future CIP-014 facility and of the process that would handle mitigation of future CIP-014 facilities.”
Exelon brought the changes of the issue charge to the April PC meeting and agreed to delay a vote until the May meeting so discussion could be conducted with stakeholders. “We made an effort to make it clear that we’ll be focused on the avoidance of future assets,” Exelon’s Robert Taylor said.
Erik Heinle of the D.C. OPC presented an alternative to the redline version of the issue charge that included developing nondisclosure agreements regarding assets under CIP-014. His proposal was rejected, with 61% voting against it.
Heinle said stakeholders agree on wanting to address critical infrastructure avoidance. He said the biggest issue is determining the appropriate levels of confidentiality for projects.
“We should work on getting the policy right with mitigation, with avoidance, with confidentiality and send it to FERC and say, ‘This is the best policy that we’ve drawn up to address these facilities,’” Heinle said.
Poulos said the Critical Infrastructure Stakeholder Oversight group is very close to finishing its work. But he said the Exelon changes removed the consumer interest from the Tariff in regards to CMPs. Poulos said the changes proposed by Exelon are not typically done in an issue charge, and he indicated that he may bring the issue up directly to the MRC.
Taylor said Exelon incorporated stakeholders’ feedback in its revisions. “I think it’s fairly inappropriate to come out of the gate saying that if we don’t get our way out of the Planning Committee vote, we’re going to take it straight to the MRC,” Taylor said. “We’ve really tried to bend over backwards to take into account the concerns that have been raised.”
Emily Smithman of the New Jersey Board of Public Utilities said the BPU supported the original issue charge and disagreed with Exelon’s changes. Smithman said the BPU views the changes as increasing noncompetitive transmission investment in PJM.
Taylor said Exelon doesn’t see the mitigation of critical infrastructure as a competitive process, saying FERC has ruled that competition is not suitable for the assets.
“I don’t think anybody has envisioned or proposed that there would be a competitive window for these projects,” Taylor said.
PMU Placement First Read
PJM is considering using a “quick fix” Tariff revision to address the RTO’s plans to expand the use of synchrophasors and formalize their placements into the RTEP.
Shaun Murphy of PJM reviewed the problem statement, issue charge and proposed solution during a first read to require synchrophasors — also known as phasor measurement units (PMUs) — in all new substations and major construction projects to monitor bus voltage and line flows. The committee will be asked to approve the issue charge and endorse the proposed manual language at the June PC meeting under the quick-fix process detailed in section 8.6.1 of Manual 34.
In the PJM presentation, Murphy said additional language is being proposed for section 1.4.1.3 of Manual 14B that would include a PMU Placement Strategy (PPS) to identify the synchrophasor device coverage needed to support the RTO’s real-time synchrophasor applications. The PPS would include placement targets and required operational dates to guide installation plans and make mandatory a program that is currently voluntary.
Murphy said instituting the PPS would close the gap between research and real-time control room use, and improve data reliability and oscillation detection.
PJM completed a PMU data exchange with the Tennessee Valley Authority in February and expects to exchange data with Southern Co. and SPP later this year. The exchanges are intended to support reliability coordinator situational awareness and the Department of Energy’s oscillation detection pilot, an effort prompted by the Jan. 11, 2019, oscillation event. (See Oscillation Event Points to Need for Better Diagnostics.)
Murphy said the communication equipment needed at each substation costs as much as $120,000, and each substation would have two or three PMUs that cost about $10,000 each. As many as 889 projects could be created over a 12-year span if a voltage threshold of 115 kV for each unit is accepted, according to data presented by PJM.
Calpine’s David “Scarp” Scarpignato asked if the Tariff revisions would change the requirements for new generation having to install PMUs and if there would be any change for existing generators.
Murphy said PJM did not expect any changes for existing generators, but he said there could be an impact for generators on future generation projects depending on the manual language adopted.
Scarp requested that the impact on future generation projects be included in PJM’s next presentation.
Dave Mabry of the PJM Industrial Customer Coalition questioned the RTO about the cost of the initiative. According to numbers provided in the presentation, Mabry said, the cost could be as much as $135 million.
“I think my clients aren’t really sold that this technology is a need-to-have,” Mabry said. “We’re seeing it more as a nice-to-have and perhaps still not ready for prime time.”
Load Forecast Update
Andrew Gledhill of PJM provided an update on estimated COVID-19 pandemic impacts on PJM loads.
Gledhill said the high-level findings of the pandemic’s estimated impact on load has shown weekday peaks coming in 10% less than normal, or about 9,000 MW. Gledhill said the weekday peak impacts have ranged from 6.5 to 15.2%, with the largest estimated impacts happening on May 4 and 5 at 15% and 15.2%, respectively.
Energy has tended to be less affected by the pandemic, Gledhill said, with the average reduction since March 24 coming in around 7.9%. He said the hourly load shapes have been flatter than what is typically seen in the spring, and weekends seem to have been less impacted.
Gledhill said PJM has updated the RTO forecast using economic assumptions from April in place of the September 2019 forecast. He said planners intend to use the April economics for the parameters for the 2021/22 delivery year in the second Incremental Auction scheduled for July.
Whether there will be additional forecast updates has to do with the timing of the eventual 2022/23 and 2023/24 Base Residual Auctions, Gledhill said, as forecasters are still waiting for guidance on when the BRAs will run.
“This is an event that we’ve never seen,” Gledhill said. “So, getting as much information as possible is key to understanding how it’s affecting load and how it might affect load in the next several months or year.”
Transmission Expansion Advisory Committee
Beaver Valley Reinstatement Cuts $93M in Tx Spending
The reinstatement of the Beaver Valley nuclear plant will eliminate $93 million in planned transmission upgrades, PJM told the Transmission Expansion Advisory Committee.
FirstEnergy Solutions (FES) had filed a deactivation notice for the two-unit, 1,872-MW nuclear plant in Shippingport, Pa., in March 2018, targeting a 2021 retirement. But Energy Harbor, the new name for FES after emerging from Chapter 11 bankruptcy in February, told PJM in March it would keep Beaver Valley in operation, citing Pennsylvania’s plan to join the Regional Greenhouse Gas Initiative. (See Beaver Valley Nuclear Plant to Say Open.)
Beaver Valley Nuclear Power Plant
PJM initially identified $414 million in needed transmission upgrades after FirstEnergy announced the retirements of the Davis-Besse, Perry and Beaver Valley nuclear plants and six coal plants in 2018. The RTO reduced the projects to about $216 million after Davis-Besse, Perry and three coal units were reinstated last July.
With the reinstatement of Beaver Valley in March, the price tag has been cut to $123 million, PJM’s Phil Yum said.
He said eight baseline projects totaling $94 million are either already built or too far along in construction to cancel. Three other baseline projects totaling $8 million are still required for identified violations from the remaining deactivations, Yum said.
PJM’s re-evaluation also identified a needed $21.4 million upgrade to the 138-kV Smithton-Shepler Hill Junction line (B3214), Yum said.
All pending baseline projects are currently on hold, Yum said, and a final decision on canceling the projects will occur after the completion of required RTEP analysis and interconnection service agreements (ISAs) for affected generation queue projects.
The Beaver Valley reinstatement was included in the 2025 RTEP model build, Yum said.
TO Supplemental Projects
TOs presented more than $300 million in supplemental project solutions to the TEAC.
American Electric Power
AEP will spend $120 million to reconductor or rebuild 18 miles of 138-kV lines and install a 138-kV +/-75-MVAR Statcom system for dynamic voltage support as part of a project in response to a customer request for new service west of Cameron, W.Va. The forecasted peak demand is 30 MW initially, with long-term prospects of 90 MW (AEP-2018-OH032). The $120 million project will address strains on the local 138-kV system.
Commonwealth Edison
Commonwealth Edison will spend $65 million to rebuild the 345-kV Itasca bus as an indoor GIS double ring bus expandable to breaker-and-a-half connecting four lines and two transformers (ComEd-2020-002).
ComEd also plans to spend $55 million to rebuild the 345-kV Elmhurst bus as an indoor GIS double ring bus expandable to breaker-and-a-half connecting two lines and three transformers (ComEd-2020-003).
Both projects are needed to replace straight bus designs that do not meet current standards.
Dominion Energy
Dominion Energy Virginia will interconnect a new substation by cutting and extending Line 2137 (Poland-Shellhorn) about a half mile to the proposed Aviator Substation with a four-breaker ring arrangement to create an Aviator-Poland line and an Aviator-Shellhorn line at a cost of $22 million. The new Aviator substation is needed to accommodate a new data center campus in Loudoun County, Va., with a total load in excess of 100 MW (DOM-2020-0003).
It also will spend $40 million to construct a 230-kV underground line from the Tysons Substation to a new Springhill Substation to replace the portion of existing overhead Line 2010. It will install a 230-kV, 50-100-MVAR variable shunt reactor at Tysons. The project, which will span about three-quarters of a mile, was requested by a customer and Fairfax County to allow construction of a planned mixed-use development (DOM-2020-0010).
PJM on Friday hosted an Interregional Planning Stakeholder Advisory Committee (IPSAC) meeting to provide input for the development of the Northeast Coordinated System Plan (NCSP), which outlines planning activities conducted jointly by ISO-NE, NYISO and PJM.
Nebiat Tesfa, a PJM transmission planning engineer, said the group will continue coordinating studies across the grid operators’ seams and issue the next NCSP by spring 2022.
PJM interconnection queue projects jointly coordinated with ISO-NE and NYISO | PJM
PJM Tx Planning
Tesfa presented updates on PJM’s planning processes and Regional Transmission Expansion Plan (RTEP).
She noted FirstEnergy Solutions’ March announcement that it would withdraw its deactivation of the 1,872-MW Beaver Valley nuclear plant in Shippingport, Pa., citing Pennsylvania’s efforts to join the Regional Greenhouse Gas Initiative (RGGI). (See Beaver Valley Nuclear Plant to Stay Open.) The company had filed a deactivation notice for the plant in March 2018, targeting a 2021 retirement.
PJM generation deactivation update since Nov. 1, 2019 | PJM
“As a result, there are several baseline upgrades identified,” Tesfa said. “Beaver Valley only recently announced the withdrawal of their deactivation request, and as a result, PJM is evaluating the impacts of the reinstatement of those generators, and we’ll provide the results in the future meetings.”
PJM is working to determine which transmission upgrades it can cancel in response FirstEnergy Solutions’ reversal, she said.
ISO-NE Tx Planning
Brent Oberlin, ISO-NE director of transmission planning, presented updates on the RTO’s transmission planning evaluations of the New England system.
Oberlin highlighted Tariff changes to enhance the competitive transmission solicitation process, which FERC approved in December, including:
creation of the Selected Qualified Transmission Project Sponsor Agreement (SQTPSA) to help determine the design and build of a new transmission project;
improvements to Attachment K to the Open Access Transmission Tariff; and
modifications to Schedule 12C of the Tariff to establish a new baseline for consideration of localized costs.
ISO-NE has completed a number of transmission planning studies, driven by the upcoming retirement of the Mystic generators in Connecticut, he said.
The RTO’s competitive transmission solicitation for Boston garnered 36 proposals from eight qualified parties by the March 4 deadline, Oberlin said. The RTO is confident that some proposals in the phase one study process are going to be available for New England ahead of the June 1, 2024, retirement date for Mystic 8 and 9. (See “Faster Boston RFP,” NEPOOL Participants Committee Briefs: May 7, 2020.)
ISO-NE received two submittals this year on the region’s public policy transmission planning process, one from National Grid and the other from the Episcopal Diocese of Rhode Island, each of whom identified public policy requirements or other actions that, in their view, drive transmission needs, he said.
“All that information was forwarded to the New England States Committee on Electricity (NESCOE), and the way that works is they have the option of providing a response to the ISO … and they can also supplement that information,” Oberlin said.
NESCOE responded that it does not think ISO-NE should be studying any public policy transmission upgrades for this cycle, he said.
“We did add two new projects, which were to address the time-sensitive needs in Boston,” Oberlin said.
Thirty-four new projects were added to the asset condition list, the lion’s share of which were for replacing aging infrastructure, such as wooden poles damaged by woodpecker holes, he said.
NYISO Tx Planning
Philip Chorazy, NYISO senior engineer for public policy and interregional planning, presented updates on the ISO’s Comprehensive System Planning Process (CSPP).
The 2020 Reliability Needs Assessment (RNA) will incorporate impacts of a new peaker rule into its base case reliability analysis, Chorazy said. The New York State Department of Environmental Conservation adopted a regulation to limit nitrogen oxide emissions from simple cycle combustion turbines, or peaking units, he said. The new regulations go into effect May 1, 2023, with initial rate limits of 100 parts per million on a dry volume basis, corrected to 15% oxygen. (See NY DEC Kicks off Peaker Emissions Limits Hearings.)
NYISO Congestion Assessment and Resource Integration Study (CARIS) phase I congestion groupings | NYISO
The RNA also will include a scenario evaluating the impacts of 70% of energy produced from renewable resources by 2030 for both transmission security and resource adequacy, with the first pass of RNA results to be presented next month, Chorazy said. New York’s Climate Leadership and Community Protection Act (A8429) signed into law last July calls for 70% of the state’s electricity to come from renewable energy resources by 2030, doubles the distributed solar generation target to 6 GW by 2025 and nearly quadruples the previous offshore wind energy target to 9 GW by 2035.
Chorazy also explained that the ISO’s the Congestion Assessment and Resource Integration Study (CARIS), which determines the top three congested locations in the New York Control Area and is intended to develop generic solutions for transmission, generation, demand response and energy efficiency. The 2019 CARIS Phase 1 draft report was presented at the ISO’s Electric System Planning Working Group in April, with a final draft scheduled for July, pending Board of Directors approval.
NYISO will initiate the 2020/21 Public Policy Transmission Planning Process cycle in August by issuing a solicitation for proposed transmission needs driven by public policy requirements, Chorazy said.
A regionally planned undersea transmission network interconnecting an expected surge in offshore wind projects would save New England developers and ratepayers more than $1 billion in onshore grid upgrades, The Brattle Group said in a study released Thursday.
Brattle prepared the study on behalf of transmission developer Anbaric Development Partners, which has proposed the Southern New England OceanGrid, an open-access network that would interconnect future offshore wind projects in the federal wind lease area off the coasts of Rhode Island and Massachusetts.
Brattle compared the costs of such a proposal to the expected costs under the current approach of each offshore project using one generator lead line (GLL) to interconnect to an onshore point of interconnection (POI). Four projects under development worth 3,112 MW — Vineyard Wind, Mayflower Wind, Revolution Wind and Park City Wind — already plan to use their own GLLs.
The Brattle Group compared two different scenarios: one in which each offshore wind project interconnecting to the grid uses its own individual line (left), and another in which a shared, open-access offshore grid is planned. | The Brattle Group
But New England will need possibly more than 40 GW of offshore wind by 2050 to meet states’ decarbonization goals — or as much as 1.5 GW every year, Brattle said. If every project followed the current approach, it could lead to major onshore transmission overloads, the group found.
“These overloads, and the massive amounts of marine cabling, could be reduced dramatically with a planned approach,” Johannes Pfeifenberger, a principal at Brattle, said in unveiling the study during a webinar hosted by Massachusetts-based State House News Service on Thursday.
| Massachusetts CEC
Pfeifenberger explained that because projects would share HVDC lines under a planned approach rather than individual HVAC lines, in addition to reducing costs and congestion, a planned grid would also lessen the amount of marine trenching needed, mitigating damage to the undersea environment. Power line loss would also be reduced, as the length of cables would be shorter.
Brattle broke down its comparison into two phases: one based on states’ current procurements besides the four projects already expected to use GLLs (2.8 GW) and an expected extra 800 MW; the second based on using up the remaining lease area (about 8.2 GW).
Under both the baseline scenario, which assumes projects continue to use their own GLLs, and the planned scenario, Phase 1 would see 3,600 MW in transmission capacity built. But under the current approach, nine HVAC lines stretching a combined 694 miles would be built, with “significant onshore transmission overloads” in Southeastern Massachusetts. Under the planned scenario, only three HVDC lines totaling 356 miles are built, with only “minimal” congestion near the POI at the Mystic Generation Station in Everett, Mass.
‘A Bowl of Spaghetti’
The differences become even more stark in Phase 2. In the baseline scenario, onshore transmission becomes even more congested and spreads across Massachusetts, Rhode Island and Connecticut. More individual GLLs are added, crisscrossing each other under the sea before they reach their POIs: “a bowl of spaghetti,” as Pfeifenberger described it, “of many lines; 18 [to] 20 lines emanating from the offshore wind lease area and interconnecting at various points onshore.”
In the planned scenario, additional HVDC lines are bundled with existing ones, untangling the “spaghetti” to create only four discernable routes to about the same number of POIs.
Overall, under Brattle’s planned scenario:
total transmission costs are 10% lower, with a 65% reduction in onshore upgrade costs offsetting an expected 22% increase in offshore construction costs;
line losses are about 40% lower;
line mileage is about 49% lower; and
ratepayers would save about $20 million annually.
“Importantly, you also create more competition under the planned approach,” Pfeifenberger said. “You would have people compete for building the offshore grid; then you would have wind developers for interconnecting their projects to onshore grid locations. … Offshore wind developers would not have to worry about the transmission component of their projects.”
The risk of stranded assets is also lessened, Brattle said.
“Without a well-planned offshore grid, some of the existing offshore lease sites may not be economic to develop,” the study says. “After developers interconnect the bulk of their lease sites, it may be cost-prohibitive to interconnect the residual areas (of perhaps 50 to 250 MW each) using AC generator lead lines sized to carry about 400 MW each.”
There’s also “a limited number of landing sites for offshore wind transmission in New England,” said Pfeifenberger’s associate at Brattle, Walter Graf. “If each offshore wind project requires a separate cable interconnection to the onshore transmission system, viable cable routes become really constrained.”
Anbaric and other transmission developers, eager to capitalize on the growing interest in offshore wind, have long been advocating for the benefits of offshore transmission planning. (See Anbaric Pushes Offshore Grid Plans.) But Brattle’s study appears to be the first attempt to quantify those benefits.
Anbaric’s proposed Southern New England OceanGrid | Anbaric
“Brattle’s research underscores the pivotal role of transmission policy in the development of New England’s offshore wind industry,” Anbaric said in a statement. “By relying on landing points closer to population centers and at robust onshore grid locations, a planned system reduces grid congestion and the need for expensive, disruptive onshore transmission projects that could hinder the growth of offshore wind.”
States have shown interest in such an approach. (See Mass. DOER Explores Transmission for OSW.) And webinar attendees, many of which were state regulatory staffers, were eager to get their hands on the Brattle study, if the side chat room in the webinar was anything to go by: Pfeifenberger repeatedly linked to his presentation as Graf spoke in response to requests from those apparently unaware they could see his previous answers.
Brattle compared a planned offshore grid to previous renewable-facilitating transmission projects, such as Texas’ Competitive Renewable Energy Zones and MISO’s multi-value projects. “New England could adopt a similar approach to planning transmission infrastructure to support offshore wind,” it said.
The PJM Operating Committee on Thursday unanimously approved an initiative to consider rule changes for the substitution and termination of black start resources.
David Kimmel of PJM reviewed the problem statement and issue charge, focusing on four areas in the Tariff that the RTO identified as in need of updates: testing requirements for black start resources not compensated through Schedule 6A; black start unit substitution rules; black start termination rules; and the black start capital recovery factor. (See PJM Eyeing New Black Start Changes.)
In March, PJM suspended an initiative considering fuel security requirements for black start units, which faced opposition from state regulators and consumer advocates. (See PJM Backs off Black Start Fuel Rule.)
Stakeholders also unanimously approved an amendment to the problem statement and issue charge proposed by Independent Market Monitor Joe Bowring to add an update to rules governing oil-carrying costs and minimum tank suction levels (MTSL).
Bowring said the MTSL issue has been left unaddressed in the Tariff for several years, leaving no clear language as to how shared resources like fuel tanks should be treated. He said many black start units charge customers for 100% of the MTSL. That charge is overstated when the tanks were sized to meet the needs of the generating units that share the tank and that use significantly more oil than the black start requirements, he argues.
The Monitor recommends that only a proportionate share of the MTSL for oil tanks shared with other resources be allocated for black start units, Bowring said, as this would help ensure that only costs directly related to black start service are paid by customers. (See “Black Start Fuel Assurance,” PJM Operating Committee Briefs: May 1, 2018.)
Becky Davis of PJM provided education on black start testing, termination rules, substitution and the capital recovery factor.
The work time on the black start issue is expected to take two to three months, and implementation of the changes needed to governing documents is estimated to take about six months following the potential Tariff changes.
COVID-19 Still Impacting Load
PJM’s Stephanie Monzon reviewed the April operating metrics, pointing to an hourly average error in load forecasting of 2.61% and a peak error of 2.31%.
Monzon said PJM continues to see the effects of state stay-at-home orders resulting from the COVID-19 pandemic and the impacts of warmer weather on load forecasting. Monzon said forecasters have predominantly over-forecasted on most days but remain within the target error of +/-3%.
Gary Greiner, director of market policy for Public Service Enterprise Group, asked about April 13, when PJM’s forecast fell short by more than 8%.
Daily peak forecast error (April) | PJM
Monzon said there was an unexpected morning peak in the Mid-Atlantic region. As the control room operators were adjusting for the morning peak, Monzon said, the models were trying to adjust for a different expected peak.
Greiner said that when the operator adjusts the forecast, that adjustment becomes the reported forecast and can have a major impact on pricing.
“It seems like I’m being nitpicky, but this is a huge driver of price, so it’s an important error to minimize,” Greiner said.
Monzon reported that the only spinning event for the month was also on April 13, lasting for eight minutes from 3:53 to 4:01 p.m. in the Mid-Atlantic Dominion sub-zone. Monzon said the event consisted of a Tier 1 estimate of 433 MW and a Tier 1 response of 207.2 MW.
She also said that overall, April was a quiet operational month, with five reserve sharing events with the Northeast Power Coordinating Council, 12 post-contingency local load relief warnings and eight high system voltages.
Two shortage cases were also approved, Monzon said, with both occurring on April 30 at 11:55 a.m. and 12:05 p.m. She said PJM was seeing generation that was expected to serve load start staggering online and had some generation trip off the system.
The Market Implementation Committee will be asked next month to choose between a PJM proposal and one from the Independent Market Monitor to resolve pricing and dispatch misalignment issues in the RTO’s fast-start pricing plan.
At the MIC meeting Wednesday, PJM’s Tim Horger outlined the RTO’s plan, which calls for three “work streams”: short-term market changes to address pricing alignment; LMP verification “enhancements and clarifications”; intermediate operational changes to implement more “regimented” real-time security-constrained economic dispatch (RT SCED) case approvals; and long-term operational changes to investigate changing SCED timing and consider previous dispatch instructions.
PJM’s proposed short-term fixes align the locational price calculator (LPC) to use the reference RT SCED case for the same target time. LPC would calculate prices for the interval from 11:55 a.m. to 12 p.m. using the RT SCED solution for a 12 p.m. target time.
“PJM is committed to both the short-term changes and the intermediate changes,” Horger said. “We will be moving forward with these.”
Proposed short-term implementation | PJM
Rebecca Carroll provided a timeline for the PJM intermediate solution that calls for conducting operator training and making software changes to limit automatic execution of RT SCED cases to once for every five minutes. Additional cases may be manually executed and approved as needed by dispatchers under what PJM calls this “intermediate” change.
Carroll said PJM already switched from a three-minute interval to four minutes for operators in February, moving closer to the desired five-minute dispatch interval. Carroll said no adverse impacts to pricing were discovered with the time change, but she said closing the gap gives less flexibility for operators to make changes in real time and urged being “cautious” before taking the next step.
The “more regimented five-minute case approval [is] very different from what PJM’s operators see today and have done [as long as] they’ve worked for PJM,” Carroll said. “It’s definitely going to be a philosophy shift in the control room.”
Catherine Tyler of Monitoring Analytics presented the Monitor’s proposal, which was originally the joint package between it and PJM. The RTO withdrew from the proposal at the April 15 MIC meeting.
Tyler said the proposal includes changes to dispatch SCED calculations and settlements, while the PJM proposal only includes making the settlement changes.
“The difference is not in the timing of implementation so much as commitment to making all of the changes that need to be made,” Tyler said.
Carroll and Adam Keech, vice president of market services, insisted the RTO is committed to making the changes, although it can’t say when. “PJM is planning to move forward to a five-minute periodic dispatch,” Keech said. “We need to take operational precautions … we need to learn along the way.”
Stability Limits in Markets and Operations
PJM’s Joe Ciabattoni told the MIC that the RTO could support the Monitor’s proposal to use capacity constraints to curtail generating output when needed to maintain stability during maintenance outages or continue using thermal surrogates.
Generating units must sometimes be reduced below their normal economic max limit if a planned or unplanned transmission outage presents stability problems that could result in damage to the units.
After stakeholder discussion and feedback at April’s MIC meeting, “PJM can still jointly sponsor the existing package with the IMM but can also support the status quo,” Ciabattoni said. (See “Work Continues on Stability-limited Generators,” PJM MIC Briefs: April 15, 2020.)
Ciabattoni said some of the feedback received from stakeholders was that the stability constraint or generator output constraint doesn’t fully resolve the issue that the LMP would not be aligned with the dispatch signal. Current rules require the RTO to implement a thermal surrogate to reflect the stability constraint in the day-ahead and real-time markets and to bind the constraint, affecting the unit’s dispatch.
Tyler reviewed the Monitor’s proposal. It says surrogate constraints are not modeled consistently in the day-ahead and real-time markets, resulting in differences that traders can take advantage of.
PJM’s Thomas DeVita provided an update on the RTO’s response to a complaint filed with FERC last month over its forfeiture rules for financial transmission rights.
XO Energy asked FERC to order PJM to change its FTR forfeiture rule or abandon it and adopt “a structured market monitoring approach” like the one used by Trader Challenges PJM FTR Forfeiture Rules.)
DeVita said he couldn’t give specifics as to how PJM is going to respond to the complaint, but he said the RTO’s answer will focus primarily on compliance with FERC’s January 2017 order (EL14-37). In that order, FERC instructed PJM to change how it implements the forfeiture rule, saying the RTO’s focus on individual transactions failed to capture the impact of a market participant’s overall portfolio of virtual transactions on a constraint. (See FERC Orders Portfolio Approach for PJM FTR Forfeiture Rule.)
PJM filed Tariff revisions in April and June 2017 describing its new approach (ER17-1433). In September 2017, the RTO began billing forfeitures based on its new approach, XO said in its complaint, even though the commission has never acted on it.
“It’s been pending at FERC for three years, which is a significant amount of time, even by FERC standards,” DeVita said.
Comments on the XO complaint are due June 1.
PJM Seeking Consultant on ARR FTR Task Force
PJM is seeking a consultant to aid the ARR FTR Market Task Force in a review of the FTR and other markets.
PJM’s Dave Anders said the consultant is being hired in response to a recommendation of the Report of the Independent Consultants on the GreenHat Default, which called for expert help “to conduct a general review of the FTR market and other PJM markets in order to evaluate risks and rewards of structural reforms.”
After focusing primarily on the education portion of the key work activities, Anders said the task force has reached the point of needing to engage expert help in the review process.
The scope and timing of the review is currently being developed, Anders said, with PJM looking at the task force’s remaining key work activities to determine what can be accomplished and what should be put on hiatus during the external consultant review. The scope and timing plan will be discussed at the next task force meeting on May 27, Anders said, which has been cut back to a half-day of discussion.
Gary Greiner, director of market policy for Public Service Enterprise Group, asked if PJM has a sense of what the external consultant’s mission will be. He said it would be important to have an idea of the scope of the work ahead of time in order to pick the right consultant.
Anders said PJM is currently working on the scope and welcomed ideas from stakeholders on what they would like to see included in the work.
“We want to share the scope with stakeholders, but we’re not really ready yet because it’s still in development,” Anders said. “The selection is going to be interesting because there certainly are a number of experts out there that have deep knowledge of the products and the market.”
‘Quick Fix’ for NITS Rule
The MIC approved an issue charge and a “quick fix” Tariff revision to address a regulatory change in Ohio concerning the billing of network integration transmission service (NITS). PJM requires load-serving entities to sign NITS agreements and post collateral based on their peak market activity. The expected duration for Tariff revisions is two to three months. (See “‘Quick Fix’ on PMA Credit Requirements,” PJM MIC Briefs: April 15, 2020.)
If another television commercial or online public service announcement intones this lazy, probably insincere attempt to offer comfort during our collective pandemic experience, I might throw my laptop or television out a window. I might — except, because I’m largely confined these days to a single-story building, it wouldn’t result in the effect or satisfaction that is supposed to accompany this fit of pique. Cranky? Yes, I am! Along with many of my fellow pandemic inmates in cell block H. But while out in the exercise yard walking the dog recently, it struck me that another addition to our virus vernacular, “flatten the curve,” might offer a useful way to think about emerging challenges facing electric grid operators.
As we now unfortunately have all come to understand, in pandemic terms, “flattening the curve” refers to slowing the otherwise exponential spread of a virus to avoid overwhelming limited health care infrastructure and human resources. The analog in our industry is “flattening or shifting the peak,” and it’s not something we’ve historically done well.
Years ago, I likened grid planning and resource adequacy to a church designed to ensure every congregant, visitor, curious heathen, adherent to family tradition and the like was guaranteed a seat for Easter services, with 15% more pews added over the forecast attendance for good measure. As times changed, I shifted toward a more secular illustration: the example of a fictitious ordinance by the city of New Orleans requiring construction of hotels to cater to every person who might want to attend Mardi Gras, plus a prudent reserve. That’s a lot of excess capacity to expect the local hospitality industry to carry over the many sweltering, hurricane-threatened months when most sane tourists would opt for Maine or Yosemite over Bourbon Street.
The point was not to suggest that electricity should be planned and provided like church pews or hotel rooms. Society values continuous, on-demand electricity differently and for many good reasons. But still, the laws of economics aren’t suspended when it comes to our industry. Carrying large, fixed costs associated with infrastructure lying fallow for months on end is either quickly unsustainable or results in high tariffs that over time shift the supply-and-demand equilibrium, resulting in a suboptimal allocation of consumer and producer surpluses and reduced total economic well-being. In other words, in most industries, while shortage may not be a good thing, it is at least a necessary evil.
For grid operators and planners, demand is still largely unexposed or is inelastic to price. Shortage isn’t an option. And the price of electricity, despite being delivered like a guaranteed hotel room during Mardi Gras, is still a good deal as a “value proposition” for most consumers. But from the perspective of those interested in designing organized wholesale electricity markets, the economic inefficiency of our industry’s infrastructure profile keeps people working on demand response, advanced metering and regulatory reform to expose more customers to actual real-time prices for electricity in the wholesale market. Here, the hope is that prices can be harnessed to change consumption behavior to flatten peaks through a curtailment or temporal shift of consumption. As mentioned, despite huge theoretical promise, as an industry we have had modest success at best in identifying and controlling discretionary consumption through either price or programs.
Today, new fronts have opened to tackle this problem. The motivation here isn’t the economic inefficiency associated with transmission and generation infrastructure in waiting. Rather, the concern is operational. Public tolerance to ever-expanding infrastructure, particularly transmission, is limited. Let’s face it: Electric infrastructure has less aesthetic appeal than a cathedral and arguably even less than a Trump Tower hotel. More salient, is the changing generation resource mix and, in particular — through policy mandate, customer preference or otherwise — the increasing penetration of intermittent, renewable wind and solar generation. We’ve all heard of CAISO’s “duck curve” and seen ramp rates become steeper year after year. In a carbon-constrained world, the role of flexible natural gas generation to “back up” and follow load is viewed as a temporary solution at best. So, we redouble efforts to conform an uncooperative supply curve populated by intermittent generation to an inviolate load curve.[efn_note]Admittedly one can find isolated, but significant, efforts by certain large customers to change consumption patterns to better align to the limits of the supply curve. For example, Google, which has a goal of real-time, 24/7 zero-carbon operations, has begun shifting the timing of computing functions that are electricity intensive at data centers “to when low-carbon power sources, like wind and solar, are most plentiful.” https://blog.google/inside-google/infrastructure/data-centers-work-harder-sun-shines-wind-blows/We can hope this kind of participation by large data center customers will eventually involve a more complex optimization of business needs, the availability of renewable electrons, electricity price and communication costs across multiple data centers located in different geographies and in different electricity markets. These actions will change load shape to better conform to a changing supply shape.[/efn_note] We ruminate over ideas such as building more transmission to move solar power from Arizona at the speed of light to meet the 8 a.m. morning pick-up in Los Angeles when the sun is still low in the sky over coastal California, and then push overabundant California solar back to Phoenix as the sun begins to set out there. What about batteries and the promise of other advanced clean technologies to add to our supply mix? It’s old news to note that increasing reliance on renewable resources is creating new challenges for system operators responsible for reliably ramping a system up and down to meeting its peaks.
Timing of March/April weekday peaks in PJM | PJM
Fine. But what has the pandemic got to do with any of this? The answer is what today’s grand and involuntary social experiment shows about grid performance and the attendant price outcomes associated with new and different load curves. And while quarantines and shutdowns may persist, they are finite. So, the more interesting point to consider is how more permanent social distancing, work from home and staggered industrial production scheduling could change the load shape, and the grid operation, carbon and economic implications that in turn would follow from this change.
Recently, PJM published data illustrating aggregate impacts of the pandemic situation on its operations over the past six weeks. Of course, it showed overall energy consumption had declined across the region, in a range of about 6 to 8%. It also showed that the peaks had declined by a greater amount — more like 10 to 12%. But things get more interesting looking at the ramp or load shape. Yes, the morning pick-up started later, but it also appears less concentrated in the 7 to 9 a.m. hours and spread out over a longer time period[efn_note]The graph on page 9 of the following document, in particular, illustrates changes to peaks: https://pjm.com/~/media/committees-groups/subcommittees/las/2020/20200505/20200505-item-03-covid-19-impact-update.ashx[/efn_note] — a “flattening of the curve,” if you will. Other operators are also showing evidence of a more gradual and delayed morning peak just like PJM; implications to the evening peak are less conclusive.[efn_note]NYISO spokesperson Zach Hutchins reported: “We continue to observe a more gradual morning ramping period.” (April 2, 2020 9:45 a.m.) https://www.nyiso.com/covid[/efn_note]
I’m not one to characterize anything associated with our current human health and economic catastrophe as a “silver lining.” But very early observations suggest that certain “new normal” post-COVID scenarios affecting how society lives and works may change load behaviors in a way that decades of price incentives and regulatory programs have largely failed to do[efn_note]The data we have after just six weeks of a shutdown that has occurred during the industry’s shoulder season serves as only a glimpse of what we might expect by way of more permanent changes in load profiles.[/efn_note] — behavioral changes that cause a temporal shift in electricity consumption, flatten the peak and, thus, reduce the strain on a supply side increasingly challenged to meet peaks as it transitions toward cleaner, carbon-free resources.[efn_note]It’s also sometimes easy to forget that in order to meet decarbonization goals, the electric sector is going to have to do more. The electrification of transportation, industrial processes and heating in buildings will increase total consumption and also affect consumption patterns.[/efn_note]
To further burden the analogy, a monthlong Mardi Gras allowing access to more people on less costly terms may be less intense, less fun and have a less obvious crescendo, but it’s probably healthier. More gradual load curves that reduce reliance on fossil-fueled, load-following generation promise beneficial carbon reductions while buying additional time for the development of clean supply side and storage technologies.
It remains to be seen — in fact, I have heard these are “uncertain times” — whether we will return to the “good old days” or instead a “new normal” of social distancing with different patterns of work and life. I hope it’s Door No. 1. But the thought nagging me is that we might be better positioned to address our other evolving global crisis, the climate, if we are forced for health reasons to change how we live and work and, as a consequence, we flatten the curve; that is to say, the load curve.
Vincent Duane is presently consulting through his firm Copper Monarch, LLC. He was previously the Senior Vice President: Law, Compliance & External Relations at PJM Interconnection, LLC.
Texas regulators last week adopted rules establishing a cybersecurity monitor and coordination program for investor-owned, municipal and cooperative utilities that count on their voluntary participation (49819).
The amendments to the Texas Public Utility Regulatory Act (PURA) don’t require utilities to participate or to submit documents to the monitor. Utilities have made the rules’ voluntary nature a key issue in the proceeding.
But that left members of the Public Utility Commission nonplussed over comments made in the docket. Chair DeAnn Walker said during the commission’s open meeting Thursday that she was “taken aback” and “floored” by some of the stakeholders’ comments “and some of the people making those comments.”
The amendments are the result of two bills approved last year by the state legislature. Senate Bill 64 established the cybersecurity coordination program to share guidance on best practices, while SB 936 set up the cybersecurity monitor.
“Over the years, we have had input from the legislators that they clearly wanted something like this,” Walker said.
Commissioner Arthur D’Andrea said that he too was “taken aback” by the utilities’ comments, noting that the PUC has stood “shoulder-to-shoulder” with its stakeholders during the recent legislative session.
Commissioner Arthur D’Andrea
“While [the program is] voluntary, this is not an audit,” he said. “We want to protect their data, but we do expect participation and cooperation.”
When several utilities asked that “voluntary” be added to the rule, the PUC responded by saying the “voluntary nature of participation … is made clear throughout the rule.”
Monitored utilities will contribute to the program through their administrative fee to ERCOT. Those outside the ERCOT footprint will pay for the monitoring under a separate fee.
Any Texas utility “may” participate in the cybersecurity coordination program at no cost.
Commissioners Defend PUC Staff
Walker and D’Andrea both defended commission staff after they felt staff’s comments on an ERCOT Nodal Protocol revision request were devalued in a grid operator stakeholder meeting last week (NPRR1020).
PUC staff filed joint comments with ERCOT staff on NPRR1020, which clarifies that emerging battery storage technologies can be interconnected and operated as a resource. The change proposes to add a definition for “integrated battery storage system” (IBSS) and modifies the definition of “wholesale storage load” (WSL) to include IBSS.
PUC staff did not sign their individual names to their comments, while ERCOT staff did. During the Protocol Revision Subcommittee’s (PRS) meeting Wednesday, at least one stakeholder questioned why PUC staff didn’t sign their names, according to another stakeholder who requested anonymity.
“They wanted a name of a particular staff member. I find that offensive,” said Walker, who relayed her understanding of the PRS meeting based on a phone call she had received from staff.
PUC Chair DeAnn Walker makes a point during the commission’s May 14 open meeting.
PUC staff said PURA rules already allow for storage system loads integrated into a single container to be eligible to receive WSL treatment. They said the current IBSS definition “may arbitrarily exclude some integrated battery systems that do not meet all of the criteria specified in the proposed definition.”
“Therefore, [PUC] staff and ERCOT suggest revisions … in an effort to provide clearer guidance and minimize arbitrary treatment in extending WSL treatment to integrated battery systems,” agency representatives wrote. “The definition should focus on the characteristics that support extending WSL treatment to [storage systems] integrated into a single container instead of adding a new technology category to the WSL definition, which already includes the term ‘batteries.’”
“Technology is going to change. We have to be nimble to be able to change and do things with it,” Walker said. “If staff believes [NPRR1020] falls under our current rule, I find it offensive that people at ERCOT are challenging and saying that staff has no rights and has to [identify themselves].”
“Staff’s position is an institutional voice, and that should be good enough,” D’Andrea said. “This [NPRR] is already two-and-a-half years in the making. I’m already embarrassed by how long it’s taken us to nimbly account for this technology. This is the kind of thing Texas should be able to adapt to and that the markets should be able to handle well.”
The Wholesale Market Subcommittee agreed to take up NPRR1020, and ERCOT staff said it would schedule a workshop on the issue. Like the PRS, the WMS reports up to ERCOT’s Technical Advisory Committee.
ERCOT and PRS Chair Martha Henson, with Oncor, both declined to comment.
Customer Protections Extended to June 17
The commission added another month to its pandemic-related provision that suspends customer disconnections for non-payments, from May 15 until June 17, acknowledging concerns that extensions of the emergency order are being issued open meeting by open meeting (50664).
“I was really hoping at this point we would be further along in our reopening of the state,” Walker said, pointing to the Texas Panhandle and the rising numbers of COVID-19 cases related to meatpacking plants. The state reported more than 700 cases on Saturday alone.
“Those customer bills will continue to rack up,” she said. “At some point, they’re going to get a bill they have to pay.”
“I’m concerned we’re just starting to see the effects of economic disruption,” Commissioner Shelly Botkin said.
The order applies to low-income customers of vertically integrated electric utilities that operate outside of ERCOT: Entergy, El Paso Electric, Southwestern Public Service and Southwestern Electric Power Co.
In other actions, the PUC approved an amendment to the PURA that adds retail brokers or aggregators to those governed by customer protection rules for retail service (50406).
PJM will pay an Illinois wind farm at least $10 million under a FERC-ordered resettlement of incremental capacity transfer rights (ICTRs) to the Commonwealth Edison locational deliverability area (LDA), the RTO said Thursday.
On April 16, FERC ordered PJM to recalculate the ICTRs for Radford’s Run Wind Farm, agreeing with facility owner E.ON Climate & Renewables N.A. that the analysis should have used the base case for the 2015 Base Residual Auction, entitling it to 279 MW of ICTRs (EL18-183). (See PJM Ordered to Recalculate Wind Farm’s Capacity Rights.)
ICTRs — available to interconnection customers that are required to fund a transmission facility — are awarded based on how much the improvement increases the transmission import capability into an LDA. The rights are good for up to 30 years.
In 2018, the commission ordered a paper hearing after granting a complaint by Radford’s Run, which said PJM unfairly denied ICTRs for funding an upgrade identified in its system impact study to mitigate a thermal overload on the 345-kV Loretto-Wilton Center line. The 306-MW wind farm in Macon County, Ill., began operations in 2018. The commission ordered the hearing to determine whether the upgrade increased the capacity emergency transfer limit of the ComEd LDA, entitling it to ICTRs.
| E.ON
The commission’s April 16 order entitled Radford’s to receive payments for the capacity auctions held in 2016-2018 for delivery years 2019/20, 2020/21 and 2021/22. It also required PJM to resettle payments for the ICTRs and to rebill affected load-serving entities for the nearly complete 2019/20 delivery year.
On Wednesday, PJM canceled a presentation on the resettlement that was scheduled for the Market Implementation Committee. The presentation said the annual economic value of the 279-MW ComEd LDA ICTR was almost $10 million for 2019/20, $1.04 million for the upcoming 2020/21 delivery year and $5.6 million for 2021/22, as of the first Incremental Auction, which is subject to change based on results of the second and third IAs.
The $10 million payment for the nearly completed 2019/20 delivery year will be clawed back from other LSEs in the ComEd LDA. PJM said the final zonal credit rate for the ComEd zone was reduced to $2.34/MW-day from the initial rate of $3.43/MW-day per megawatt of unforced capacity obligation, a 32% cut. The resettlement will be included in the May invoices PJM expects to issue on June 5.
For the 2020/21 delivery year, the rate was reduced to $0/MW-day from 12 cents/MW-day. ICTR holders only receive revenues if the LDA in question is constrained in subsequent capacity auctions.
More than two dozen companies and coalitions filed responses to PJM’s March minimum offer price rule (MOPR) compliance filing last week, taking issue with the RTO on auction timing, floor prices, unit-specific rules and self-supply exemptions (EL16-49).
Below is a summary of the issues raised in the comments and protests filed last week.
Auction Timing
Commenters weighed in on both sides of PJM’s proposal to hold the Base Residual Auction for delivery year 2022/23, six and a half months after a final compliance order but no later than March 31, 2021.
The Electric Power Supply Association, PJM Power Providers (P3) Group, NRG Power Marketing and Calpine — whose complaint led to the December order — all called for an earlier auction.
“For its part, EPSA is deliberately refraining from wading into the details of the compliance filing in order to focus on the importance of conducting the 2022/23 BRA as soon as possible,” it said.
PJM proposed delaying the auction to as late as March 2021 if it is requested by regulators in a state that approves legislation before June 1 opting out of the capacity market for a fixed resource requirement (FRR).
PJM would seek to eliminate the first and second Incremental Auctions for delivery year 2022/23 if the Base Residual Auction is not held until December 2020. | PJM
EPSA noted that FERC’s April order rejecting rehearing of the December ruling requires PJM to make a second compliance filing June 1. “Realistically, even assuming a shortened comment period for the second compliance filing and a lightning quick turnaround on the commission’s part, it is hard to see the commission issuing an order earlier than July 1, 2020, which, under PJM’s schedule, would have the 2022/2023 BRA being conducted in mid-January 2021,” EPSA said. That would leave a forward period for the BRA of only 14 to 16 months, versus the three years under the Reliability Pricing Model’s (RPM) normal schedule.
“EPSA recognizes that PJM’s request may be moot if no state enacts FRR-enabling legislation by the end of this month, but the commission will undoubtedly be asked to extend the June 1, 2020, deadline or to deem it satisfied by something less than legislation ‘enacted’ by that date,” Calpine added. (Indeed, New Jersey regulators said the extension should also accommodate state regulatory processes. See below.)
P3 said the yearlong delay in the 2022/23 auction has already “thwarted” decisions on investments and maintenance; “projects have not been financed or refinanced” because of the lack of forward price signals.
“The delay … is well beyond the pale of acceptable. For the sake of suppliers, consumers and the sanctity of the PJM wholesale market, resumption of these auctions must become a priority for the commission and PJM,” it said. “PJM and the commission continue to look to each other to ‘make the call’ on the timing of the next auction. P3 urges the commission to end this back-and-forth and provide specific direction to PJM so these auctions can resume.”
P3 and NRG questioned whether PJM needs more than six months to prepare for the next auction, noting it proposed a 4.5-month time preparation period the subsequent BRAs.
P3 urged the commission to “settle the issue of the definition of a state subsidy” and finalize net cost of new entry (CONE) and avoidable-cost rate (ACR) values in its order on the compliance filing and give capacity resources 21 days to determine whether they are subject to the MOPR. “For those units that are considered subsidized and not eligible for an exemption, PJM and the [Independent Market Monitor] could immediately commence the unit-specific review process for those units that elect that process.
“PJM should not be idly waiting for the commission’s second order on compliance. Instead, the commission should direct PJM to commence its auction preparation following its approval in this compliance proceeding and then direct PJM, as part of the second compliance process, to derive a timeline shorter than six and a half months,” P3 said.
“Suspension of market milestones in deference to states embroiled in special interest lobbying does not simultaneously freeze all other factors that contribute to the economics of supply and demand of a 180,000-MW market, which serves 65 million customers,” NRG said.
MOPR eligibility flow chart | PJM
The company said it has spent more than $500 million over the last six years to modernize and add environmental controls to its Illinois fleet “based on a market structure that was regularly generating price signals while at the same time enhancements such as Capacity Performance were being incorporated into PJM’s capacity construct.”
“Absent RPM price signals, NRG will blindly face investment decisions for commitment years that are rapidly approaching. Environmental regulators, both state and federal, will press on with deadlines that could require near-term capital spending for compliance with regulations such as the Effluent Limitations Guidelines for Steam Electric Generating Facilities and Coal Combustion Residuals.”
NRG and P3 also noted that utilities have had to adjust their default procurement programs because of the delay.
New Jersey electric distribution companies told the state Board of Public Utilities that bidders in the state’s Basic Generation Service default procurement program were likely to include risk premiums in their bids and that some potential bidders may not participate, “which could result in higher prices in the auction,” NRG said.
State regulators, consumer advocates and environmental groups argued in favor of the Organization of PJM States Inc.’s (OPSI) call to delay the auction until as late as May 2021, several of them noting that the coronavirus pandemic caused the suspension of state legislative sessions. The Maryland General Assembly adjourned March 18, failing to complete its full session for the first time since the Civil War.
“With the commission’s recent determination that capacity resources indirectly benefiting from state default service auction process are also subject to the MOPR, the impact of the MOPR on state policies has become only more disruptive, further supporting OPSI’s request,” the Natural Resources Defense Council, the Sierra Club and the Sustainable FERC Project said.
“The FRR alternative is not the only step that states might need to take to protect consumers and state policies from the harm of the MOPR,” the environmental groups said. “States may also need to revisit the structure of their default service auctions, the manner in which state objectives relating to generation are pursued or budgets for bill payment assistance.”
Exelon — which is supporting legislation to create an FRR in its Commonwealth Edison territory in Northern Illinois — also endorsed the May date. (See Clock Ticking on Exelon Illinois Nukes Under MOPR.)
Proposed capacity auction schedule | PJM
In a joint filing, consumer advocates for New Jersey, D.C., Maryland, Delaware, Illinois and Pennsylvania said the auction schedule should allow for a “complete load forecast similar in scope and depth” to those used in prior auctions.
“The ongoing COVID-19 pandemic and attendant reduction in economic activity only highlight the need for regular updates over the coming BRAs,” the advocates said, noting that PJM’s load has dropped by an average of almost 8%, with peak impacts as high as 15%. “These significant reductions in demand will be all the more impactful because the time between the next four BRAs and the actual delivery year will be reduced from three years to as little as one year. In other words, updated load forecasts will reflect not just the long-term outlook but short- and medium-term operating conditions.”
The New Jersey BPU said PJM’s proposed extension should not be triggered only by FRR legislation. “Implementation of the FRR alternative could also involve efforts by state regulators and state regulatory processes — even where no change in legislation is required,” it said. “The [BPU], for example, has initiated an investigation into resource adequacy alternatives, which includes exploration of its own statutory authority to implement these changes without additional legislation.”
Demand Response
The PJM Industrial Customer Coalition called for Tariff changes to clarify that neither year-to-year fluctuations in customer consumption nor changes in state subsidy levels should cause an existing DR resource to lose its MOPR exemption.
The ICC said its proposed changes would “clearly distinguish between capability fluctuations that occur as a result of year-to-year modifications in consumption and the ‘step-jumps’ associated with uprates to physical capacity. The former is MOPR-exempt, the latter is not.”
Default Floor Prices
Members of the Maryland House Economic Matters and Senate Finance committees, which oversee state energy policy, complained that the default floors proposed by PJM will likely prevent many renewable resources, especially offshore wind and storage, from clearing the auction.
“The mere possibility that renewable energy and storage projects will be able to obtain resource-specific offer price floors allowing them to clear the auction does not allay states’ concerns,” they said. “The outcomes of such an idiosyncratic and opaque resource-specific offer floor process are unpredictable and therefore cannot be relied upon by state lawmakers that need to understand the costs and benefits of different legislative proposals.”
The Pennsylvania Public Utility Commission took issue with PJM’s use of “speculative” cost adders, saying MOPR floor prices “should not be ‘maximum offer prices’ but prices that reflect actual costs of competitive entry.”
Default net CONE ($/ICAP MW-day) | Maryland legislators
It said PJM’s traditional price escalation factors are at odds with the declining costs of solar, batteries and onshore wind, noting new crystalline solar PV resources’ nominal levelized cost of energy have declined from $359/MWh to $41/MWh since 2009.
For onshore wind, PJM proposed using the Energy Information Administration’s 2019 value of $1,677/kW, which the PUC said is 14% higher than any alternative published value and outside Lazard’s range of values ($1,100 to $1,500/kW).
PJM’s gross CONE value for onshore wind assumes a 17-by-2.8-MW configuration (about 50 MW). “However, PJM’s current interconnect queue as of May 6, 2020, for onshore wind projects shows an average project size of 205 MW over 80 projects,” the PUC said.
“For newer declining cost technologies, annual price adjustments should be adopted to reflect current and projected nominal costs at the time of development,” it said.
Unit-specific Rules
PJM’s proposal for unit-specific exemption requests also drew criticism, with some calling for more flexibility and Calpine calling for rigorous vetting.
“The unit-specific review process must be carefully conducted in order to ensure that it does not defeat the purpose of offer-floor mitigation,” Calpine said. “PJM and the IMM should vigorously review any such submissions to ensure that the seller has adequately demonstrated that it is reasonable to assume an asset life of more than 20 years for the specific resource at issue. As another example, to the extent that a seller relies on ‘long-term power supply contracts, tolling agreements or tariffs on file with state regulatory agencies’ in order to support its projected energy and ancillary services markets revenues, PJM and the IMM should take pains to ensure that such contracts, agreements or tariffs are not disguised state subsidies.”
In the last decade, the levelized cost of energy (LCOE) for utility-scale solar has dropped by 89% and the LCOE for onshore wind has declined by 70%. | Lazard
OPSI and the Pennsylvania PUC complained that although PJM said it would allow evidence of a longer than 20-year asset life, it proposed standardizing the other five financial modeling assumptions used to calculate resource-specific offers: nominal levelization of gross costs; no residual value; all project costs included with no sunk costs excluded; use of first year revenues; and weighted average cost.
“While each of the assumptions may have a material impact on the calculation of the offer floor, PJM only proposes flexibility with respect to the 20-year unit life element,” OPSI said. “If a resource owner maintains its financial records using real levelized costs rather than nominal, or can document residual value for its unit, or uses a different protocol for sunk costs, the resource-specific cost review process for the purpose of calculating MOPR floor prices should permit that flexibility to be reflected.”
State Procurements
Calpine also called for tightening PJM’s proposal for exempting state default service procurements.
It said the state subsidy definition should only exempt “nondiscriminatory, competitive, and fuel- and emissions-neutral state-directed default service procurement programs.”
“Without this modification, the proposed definition could allow a state to evade the MOPR by requiring a procurement process that is nominally competitive and neutral with respect to fuel type but that is structured in a way that will exclude potential competitors for the benefit of favored resources,” Calpine said.
Self-supply
Dominion Energy called for broadening the competitive exemption to include self-supply entities.
“Self-supply entities that are vertically integrated utilities, such as Dominion Energy Virginia, currently own and are developing new solar resources [that] are not part of its rate base and whose costs are ‘ring fenced’ and not recovered from ratepayers,” it said. “As a result, these resources are not receiving a ‘state subsidy’ as defined by the Dec. 19 order even though they are owned by a ‘self-supply entity.’”
OPSI called for exempting all existing bilateral contracts, saying PJM’s proposal discriminates against load-serving entities in restructured states.
The organization said it supports PJM’s proposal to exempt bilateral contracts where the buyer is a self-supply entity but said the RTO’s “justification for the exemption applies equally to other, bilateral contracts of non-self-supply entities.”
“This exemption should be extended further to include enforceable supply purchase contracts entered into by non-self-supply entities entered into prior to Dec. 19, 2019, in reliance upon then-existing commission guidance. Load-serving entities in restructured states should not be precluded from using the business arrangement provided for self-supply entities in PJM’s compliance filing.”
Voluntary RECs
The Advanced Energy Buyers Group, a coalition of large energy users, said FERC should order PJM to create “an additional pathway” for capacity resources that sell a portion of their output to a voluntary purchaser and a portion to a compliance purchaser to avoid applying the expanded MOPR to the voluntary transaction.
“PJM’s compliance filing would subject such projects to the MOPR in their entirety. That result could also limit the market for voluntary purchases of renewable energy by forcing buyers to purchase the entire output of a project to avoid the MOPR, which many buyers may not be in a position to do,” the group said.
Subsidy Determinations
The American Wind Energy Association, the Solar Energy Industries Association, Advanced Energy Economy and the Solar Council, filing jointly as “Clean Energy Associations,” asked the commission for assurances that capacity market sellers “will be allowed to rely upon guidance from PJM and the IMM” in determining which state and local programs constitute state subsidies. They urged FERC to “direct PJM to create an ongoing process for market participants to timely obtain such determinations.”
The NRDC, Sierra Club and Sustainable FERC Project called for a transparent process, including a public list of which policies have been determined to be subject to MOPR; a process for parties to submit a policy for consideration with timelines for the decision-making process; and a process for determinations to be clarified or challenged at FERC.
“Absent clear reporting requirements, expanded discovery powers for PJM and/or the Market Monitor, and possibly some form of safe harbor for resource owners, uncertainty regarding the ultimate purchaser of power is likely to result in over mitigation of resources that do not receive a subsidy but are unable to verify they do not,” the groups said.
“This kind of uncertainty, case-by-case analysis and lack of transparency or oversight is likely to result in inconsistent application of the MOPR in a manner that introduces discriminatory treatment of resources.”
American Electric Power complained that PJM’s proposed MOPR exemption for voluntary bilateral transactions was unduly restrictive. FERC said voluntary bilateral transactions were not state subsidies but “permissible out-of-market revenue.”
“PJM appeared to limit the applicability of the commission’s holding in its March compliance filing by only addressing its treatment of bilateral transactions in which one party is a self-supply entity,” AEP said.
Accounting for Federal Tax Credits
AWEA and SEIA also said that while PJM properly proposed accounting for the federal investment tax credit in default gross CONE calculations for wind and solar resources, it “does not expressly provide comparable treatment for other types of federal subsidies,” such as the federal production tax credit.
